Method and apparatus for adjustably treating a sour gas

ABSTRACT

A feed gas comprising CO 2 , H 2 S and H 2  is treated to produce an H 2 -enriched product and an H 2 S-lean, CO 2  product. The feed gas is separated to provide the H 2 -enriched product and a stream of sour gas. The stream of sour gas is divided into two parts, one of which is processed in an H 2 S removal system to form one or more streams of sweetened gas, and the other of which bypasses the H 2 S removal system, the stream(s) of sweetened gas and the sour gas bypassing the H 2 S removal system then being recombined to form the H 2 S-lean, CO 2  product gas. The division of the sour gas between being sent to and bypassing the H 2 S removal system is adjusted responsive to changes in the H 2 S content of the sour gas, so as to dampen or cancel the effects of said changes on the H 2 S content of the H 2 S-lean, CO 2  product gas.

BACKGROUND OF THE INVENTION

The present invention relates to methods and apparatus for separating afeed gas, comprising carbon dioxide (CO₂), hydrogen sulfide (H₂S) andhydrogen (H₂), to form an H₂-enriched product gas and a sour gasdepleted in H₂ and enriched in CO₂ and H₂S relative to the feed gas, andfor adjustably treating said sour gas to produce an H₂S-lean, CO₂product gas. The invention has particular application to the separationand treatment of sour syngas mixtures obtained from the gasification orreformation of carbonaceous feedstock.

The production of syngas via reforming or gasifying carbonaceousfeedstock is well known. Where the feedstock contains sulfur, such as isoften the case for solid (e.g. coal, petcoke) or heavy liquid (e.g.asphaltene) feedstocks for gasification, such processes result in aninitial syngas stream containing hydrogen (H₂), carbon monoxide (CO),carbon dioxide (CO₂), hydrogen sulfide (H₂S) and, usually, other speciessuch as methane (CH₄), carbonyl sulfide (COS) and carbon disulfide(CS₂). Commonly, the initial syngas mixture (crude syngas) is thensubjected to further treatments. In particular, the initial syngasmixture may be subjected to a water-gas shift reaction, in which atleast some of the CO present in the initial syngas mixture is convertedto further CO₂ and H₂ by reaction with H₂O in the presence of a suitableshift catalyst. This process can also result in further H₂S beingproduced, via incidental conversion of other sulfur species (such as COSand CS₂) in the syngas during the water-gas shift reaction.

Due to concerns over greenhouse gas emissions, there is a growing desireto remove CO₂ from syngas prior to use of the remaining, H₂-enriched,product (comprising predominantly either H₂ or a mixture of H₂ and CO)as a combustion fuel or for chemicals production or refiningapplications. The CO₂ may be compressed, so as to be stored undergroundor used for enhanced oil recovery (EOR). H₂S may also have to be removedfrom the syngas. If the H₂-enriched product is to be used for chemicalsproduction or refining then H₂S, if present, could be a poison for thesedownstream processes. Equally, if the H₂-enriched product is to becombusted in a gas turbine to production or refining then H₂S, ifpresent, could be a poison for these downstream processes. Equally, ifthe H₂-enriched product is to be combusted in a gas turbine to generatepower then H₂S, if present, will be converted into SO_(x) (SO₂ and SO₃),on which there are emission limits and which may, therefore, requireremoval from the combustion exhaust using expensive desulfurizationtechnology. Equally, it may not be practical or permissible to store theH₂S with the CO₂. Therefore a solution must likewise be found for costeffective removal of H₂S from the CO₂ before pipeline transportation orgeological storage.

The most commonly used commercial solution, currently, for capturing CO₂and H₂S from sour syngas mixture uses a physical solvent (i.e. liquidsolvent) absorption process, also referred to as an acid gas removal(AGR) process, such as Selexol™ or Rectisol®, to selectively separateH₂S, CO₂ and product H₂ into different streams. The H₂S-rich stream,typically containing about 20-80 mole % H₂S, is further treated toproduce sulfur, usually by a Claus process coupled with a tail gastreating unit (TGTU). The CO₂ stream is typically compressed to meetpipeline or storage specifications, and the product H₂ is either sent asfuel to a gas turbine for power generation, or can be further processedvia pressure swing adsorption (PSA) to achieve a ‘spec’ purity(typically 99.99 mole % or higher) for refining applications. However, adisadvantage of such AGR processes is that they are both costly and havesignificant power consumption.

As mentioned above, the typical method of removing the H₂S contained inthe H₂S-rich stream obtained from the AGR process is via conversion toelemental sulfur using the Claus process. This process, as is wellknown, typically involves an initial thermal step followed by one ormore catalytic steps. In the thermal step the H₂S-rich stream is reactedin a substoichiometric combustion at high temperatures to convert partof the H₂S to SO₂. The oxidant (i.e. O₂) to H₂S ratio during combustionis controlled so that in total one third of all H₂S is converted to SO₂.This provides the correct 2:1 molar ratio of H₂S to SO₂ for thesubsequent catalytic steps. More specifically, in said subsequentcatalytic steps, the 2:1 mixture of H₂S to SO₂ obtained from the thermalstep is reacted over a suitable catalyst (e.g. activated aluminium(III)or titanium(IV) oxide) to convert the H₂S and SO₂ to elemental sulfurvia the reaction 2H₂S+SO₂→⅜S₈+2H₂O. The Claus process ordinarilyachieves high (e.g. 94 to 97%) but not complete levels of sulfurrecovery and thus, as noted above, a TGTU is often also employed torecover and/or remove the remaining H₂S from the Claus process tailgas.

The Claus process is at its most economical when greater than 20 shorttons per day (tpd) sulfur (about 18000 kg/day sulfur) is to be produced,and when the H₂S concentration in the feed to the process is greaterthan 10 mole %, and more preferably greater than 20 mole %. Forproduction rates of less than 20 tpd (18000 kg/day) sulfur and/or forfeed streams that are more dilute in H₂S concentration other, moreeconomical, means of removing sulfur are generally preferred. Typically,these are catalyst-based processes that can be of the regenerable typeor the ‘once-and-done’ scavenging type and require a varying degree ofprocess complexity and operational cost depending on the processingconditions of the gas being treated. Typically, these processes are mostsuited for treating feeds with H₂S concentrations of less than 5%, andfor processes where less than 20 tpd (18000 kg/day) is to be produced(although larger units have been designed and built). These processesare typically capable of removing 99% or more of the H₂S from the feed.Industry accepted examples of such H₂S disposition technologies includethe LO-CAT and Stretford processes.

Specific examples of known prior art processes for separating H₂S,and/or other sulfur containing compounds, from a mixture include thefollowing.

US-A1-2007/0178035, the disclosure of which is incorporated herein byreference, describes a method of treating a gaseous mixture comprisingH₂, CO₂ and at least one combustible gas selected from the groupconsisting of H₂S, CO and CH₄. The gaseous mixture, which may beobtained from the partial oxidation or reforming of a carbonaceousfeedstock, is separated, preferably by pressure swing adsorption (PSA),to produce a separated H₂ gas and a crude CO₂ gas comprising thecombustible gas(es). The crude CO₂ gas is then combusted in the presenceof O₂ to produce heat and a CO₂ product gas comprising the combustionproduct(s) of the combustible gas(es). The heat from at least a portionof the CO₂ product gas is recovered by indirect heat exchange with theseparated H₂ gas or a gas derived therefrom. Where the combustible gasis, or includes, H₂S, the combustion products will include SO₂ and SO₃(SO_(x)). In one embodiment, the SO_(x) is then removed by washing theCO₂ product gas with water to cool the gas and remove SO₃, andmaintaining the cooled SO₃-free gas at elevated pressure in the presenceof O₂, water and NO to convert SO₂ and NO to sulfuric acid and nitricacid, thereby obtaining an SO_(x)-free, NO_(x)-lean CO₂ gas.

The process described in this document therefore presents a sulfurdisposition pathway in which the H₂S in the sour tailgas stream leavingthe PSA is ultimately converted to sulfuric acid after being combustedto form SO_(x). This process presents a alternative to the conventionalelemental sulfur disposition pathway and can, additionally, handledilute H₂S concentrations as well as varying total amounts of sulfur.However, market conditions could limit the economic viability of such asulfur disposition pathway, as the acid produced from such a process maybe unsalable or of sufficiently poor quality that costly neutralizationand disposal may be required.

U.S. Pat. No. 6,818,194 describes a process for removing H₂S from a sourgas, wherein the sour gas is fed to an absorber where the H₂S is removedfrom the gas by a nonaqueous sorbing liquor comprising an organicsolvent for elemental sulfur, dissolved elemental sulfur, an organicbase which drives the reaction between H₂S sorbed by the liquor and thedissolved sulfur to form a nonvolatile polysulfide which is soluble inthe sorbing liquor, and a solubilizing agent which prevents theformation of polysulfide oil. The process further comprises adding SO₂to the absorber to oxidize the polysulphide to elemental sulfur, therebyproducing a more complete chemical conversion of H₂S by reducing theequilibrium back-pressure of H₂S. The sweet gas from the absorber exitsthe process, and the sorbent stream is then cooled and fed to acrystallizer to crystallize enough of the sulfur to balance the amountof H₂S previously absorbed.

In this process, the optimum molar ratio of H₂S to SO₂ in the feedstream to the absorber is the same as that for the catalytic stage ofthe Claus process, i.e. 2:1. In one embodiment, the process is appliedto a feed stream which already contains a 2:1 mole ratio of H₂S to SO₂,such as where the feed stream is the tail gas of a Claus process whichis operated so as to produce a tail gas with this composition. Inanother embodiment, the process may be applied to an H₂S containing feedstream to which SO₂ is first added, so as to obtain the desired 2:1ratio prior to the stream being flowed through the absorber vessel. Oneexemplified way in which this may be achieved is to split the feedstream into two streams, pass one of said streams through a catalyticoxidation reactor to convert at least some of the H₂S contained thereinto SO₂, and then recombine the streams.

U.S. Pat. No. 4,356,161 describes a process for reducing the totalsulfur content of a high CO₂-content feed gas stream, comprising CO₂,H₂S and COS. The feed gas is first passed to an absorption column whereit is contacted with an a regenerable, liquid polyalkanolamine absorbentselective for H₂S. The unabsorbed gas stream, comprising CO₂ and COS andsubstantially free of H₂S is then routed to a reduction step where it iscombined with Claus off-gases and the COS reduced to H₂S. The treatedgas is then passed to a second absorption column and the unabsorbed gasis vented to the atmosphere. The H₂S-rich solvent from both absorptioncolumns is stripped in a common stripper and the H₂S-rich gas is passedto a Claus unit for conversion to elemental sulfur. The absorptionprocess described in this document is commonly referred to in theindustry as an ‘acid gas enrichment’ process.

U.S. Pat. No. 5,122,351 describes a refinement to the known LO-CAT andStretford processes of removing H₂S by conversion to elemental sulfur,whereby the catalytic polyvalent metal redox solution used in saidprocesses is recovered and re-used. This is achieved by interposing aclosed loop evaporator/condenser process in the sulfurwashing/filtering/recovery process so that wash water used to purify thesulfur and any polyvalent metal redox solution recovered from the sulfurmelter are fed to an evaporator to concentrate the redox solution to aconcentration capable of effective absorption of H₂S, and the waterevaporated in the evaporator is condensed as pure water for use inwashing and/or filtering the recovered sulfur.

US-A1-2010/0111824 describes a process for producing H₂ from ahydrocarbonaceous feed such as refinery residues, petroleum, naturalgas, petroleum gas, petcoke or coal. In the exemplified embodiment, acrude syngas comprising H₂, CO, CO₂ and H₂S, is formed by gasifyingresidue oils, quenching the raw syngas, and subjecting the quenchedsyngas to a water-gas shift reaction. The syngas is separated via PSAinto an H₂ product and a tail gas enriched in CO₂ and containing alsoH₂S, H₂ and CO. The PSA tail gas is mixed with a Claus process tail gasand the mixture supplied to a tail gas cleaning stage that uses a liquidsolvent such as MDEA or Flexsorb SE® to selectively wash out H₂S fromthe gas mixture. H₂S is then liberated from the solvent and added to thefeed stream to the Claus process.

U.S. Pat. No. 5,248,321 describes a process for removing sulfur oxidesfrom gaseous mixtures such as flue gases from power plants, smeltergases, and other gases emitted from various industrial operations. Theprocess involves contacting the gaseous mixture with anon-functionalized polymeric sorbent which is essentially hydrophobic,such as styrenic polymers, which sorbent may be employed in a PSA systemto selectively adsorb SO₂. The SO₂ rich desorption stream may be fed toa Claus reactor along with a suitable amount of H₂S to produce elementalsulfur and water.

U.S. Pat. No. 7,306,651 describes the separation of a gas mixturecomprising H₂S and H₂ using the combination of a PSA unit with amembrane. The PSA separates the feed stream into an H₂ stream and twoH₂S-rich streams. One H₂S-rich stream is recovered as a waste stream andthe second is compressed and put through a membrane to remove the H₂.The H₂S is then supplied to the PSA unit at pressure for rinsing and theH₂ returned to the PSA unit for purging. The gas mixture may, forexample, be a stream obtained from a hydrodesulfurization process in arefinery. The H₂S-rich waste stream may be fed into one of the fuel/sourgas lines of the refinery.

EP-B1-0444987 describes the separation of CO₂ and H₂S from a syngasstream produced by gasification of coal. The syngas stream, containingH₂S, is reacted with steam in a catalytic CO-shift reactor to convertessentially all the CO in the stream to CO₂. The shifted stream is sentto a PSA unit that adsorbs CO₂ and H₂S in preference to H₂, to separatesaid stream into an H₂ product gas and a stream containing CO₂ and H₂S.The stream containing CO₂ and H₂S is sent to a second PSA unit thatadsorbs H₂S in preference to CO₂, to provide a CO₂ product, stated to beof high purity, and a H₂S containing stream, the latter being sent to aClaus unit for conversion of the H₂S into elemental sulfur.

EP-A1-0633219 describes a process for removing sulfur compounds from agas stream containing sulfur compounds, such as the off-gas from a Clausprocess. The process comprises the steps of: (a) converting the sulfurcompounds to sulfuric acid, by combusting sulfur compounds other thanSO₂ to form SO₂, and catalytically oxidizing SO₂ to SO₃, which thenforms sulfuric acid in water; (b) separating the sulfuric acid from thegas stream; and (c) supplying the sulfuric acid into the thermal stageof a Claus process to allow the sulfuric acid to react with hydrogensulfide to form elemental sulfur.

Similarly, U.S. Pat. No. 4,826,670 describes a process for improving anoxygen-enriched Claus process by introducing a sulfuric acid stream intothe reaction furnace (thermal stage of the Claus process) to moderateoxygen-induced high temperatures which allow oxygen-enrichment andattendant throughput in the Claus process to higher levels.

Industries must strike a delicate balance when selecting technologiesfor processing sour feeds. A successful project must minimize capitaland operating cost while ensuring the chosen technologies canappropriately and robustly meet ever tightening emissions standards. Thefinal selection of H₂S disposition technology can, as discussed above,depend on the concentration at which the H₂S is present in the sour gasstream that is being treated. Where CO₂ is to be captured (either forunderground storage or enhanced oil recovery), the presence of H₂S inthe CO₂ product presents regulatory concerns and careful design measuresmust be in place to ensure product purity is upheld. This becomes aneven more complex problem when one considers that the amount of H₂S inthe sour gas stream can vary depending on feedstock variations, andvariations in the process used to produce and/or separate out the sourgas. Significant variation in the amount of H₂S may, in turn, lead tothe H₂S removal process becoming economically disadvantageous and/or toproduct purity and/or emission standards being compromised.

It is an object of embodiments of the present invention to providemethods and apparatus that allow for variations in the H₂S content ofthe sour gas while meeting air emissions standards and/or CO₂ purityspecifications and achieving cost advantages over conventionaltechnologies for sour gas processing.

It is an object of embodiments of the present invention to providemethods and apparatus that are capable of processing sour gas streamsfrom varying feedstocks with varying compositions.

BRIEF SUMMARY OF THE INVENTION

According to the first aspect of the present invention, there isprovided a method for treating a feed gas, comprising CO₂, H₂S and H₂,to produce an H₂-enriched product and an H₂S-lean, CO₂ product, themethod comprising:

separating the feed gas to form a stream of H₂-enriched product gas anda stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂ butbeing depleted in H₂ and enriched in H₂S and CO₂ relative to the feedgas;

dividing the stream of sour gas into two parts;

processing one part of said stream of sour gas in an H₂S removal systemto form one or more streams of sweetened gas, depleted in H₂S andenriched in CO₂ relative to the feed gas;

bypassing the H₂S removal system with the other part of said stream ofsour gas; and

-   -   combining said stream(s) of sweetened gas with said sour gas        bypassing the H₂S removal system to form a stream of H₂S-lean,        CO₂ product gas;

wherein the division of the sour gas between being sent to and processedin the H₂S removal system bypassing said system is adjusted responsiveto changes in the H₂S content of the sour gas, such that the proportionof the sour gas processed in the H₂S removal system, as compared tobypassing said system, is increased if the H₂S content rises anddecreased if the H₂S content drops.

According to a second aspect of the present invention, there is providedan apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, toproduce an H₂-enriched product gas and an H₂S-lean, CO₂ product gas, theapparatus comprising:

a pressure swing adsorption (PSA) system for separating the feed gas toform a stream of H₂-enriched product gas and a stream of sour gas, thesour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ andenriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form oneor more streams of sweetened gas, depleted in H₂S and enriched in theCO₂ relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂Sremoval system and bypassing the H₂S removal system with another part ofsaid sour gas;

a valve system for adjustably controlling the division of said sour gasbetween being sent to the H₂S removal system and bypassing said system;and

conduit means for withdrawing one or more streams of sweetened gas fromthe H₂S removal system and combining said stream(s) with the sour gasbypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a flow sheet depicting an embodiment of the present invention;

FIG. 2 is a flow sheet depicting the operation of one type of H₂Sremoval system that may be used in the present invention; and

FIG. 3 is a flow sheet depicting the operation of an alternative type ofH₂S removal system that may be used in the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a method and apparatus for treating afeed gas, comprising CO₂, H₂S and H₂, to produce an H₂-enriched productand an H₂S-lean, CO₂ product. The method comprises:

separating the feed gas to form a stream of H₂-enriched product gas anda stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂ butbeing depleted in H₂ and enriched in H₂S and CO₂ relative to the feedgas;

dividing the stream of sour gas into two parts;

processing one part of said stream of sour gas in an H₂S removal systemto form one or more streams of sweetened gas, depleted in H₂S andenriched in CO₂ relative to the feed gas;

bypassing the H₂S removal system with the other part of said stream ofsour gas; and

combining said stream(s) of sweetened gas with said sour gas bypassingthe H₂S removal system to form a stream of H₂S-lean, CO₂ product gas;

wherein the division of the sour gas between being sent to and processedin the H₂S removal system and bypassing said system is adjustedresponsive to changes in the H₂S content of the sour gas, such that theproportion of the sour gas processed in the H₂S removal system, ascompared to bypassing said system, is increased if the H₂S content risesand decreased if the H₂S content drops.

The method therefore addresses the problem of separating and treating,both economically and while still allowing for variations in composition(in particular, H₂S content), a sour gas as required to meet airemissions standards and/or CO₂ product purity specifications (e.g. forunderground storage or EOR). This is achieved by bypassing the H₂Sremoval system with part of the sour gas so that only part of sour gasis treated in the H₂S removal system, and by adjusting the proportion ofthe sour gas treated in the H₂S removal system responsive to variationsin the H₂S content of the sour gas (i.e. sending relatively more of thesour gas to the removal system and less to bypass when H₂S contentrises, and relatively less of the sour gas to the removal system andmore to bypass when H₂S content falls), so as to dampen or cancel theeffect of said variations on the H₂S content of the H₂S-lean, CO₂product. In this way, the H₂S content of the sour gas can still bereduced to a level necessary to meet air emissions standards and/or CO₂product purity specifications during times of increased H₂S content,while at the same time avoiding an unnecessary or “excessive” degree ofH₂S removal (and associated additional operating costs) when the H₂Scontent of the sour gas is lower. Thus, emissions standards and/orproduct purity specifications are maintained while at the same timeachieving a cost advantage.

As noted above, variations in upstream processes which could cause thecomposition of the sour gas to change include, but are not limited to,changes in the feedstock (e.g. coal, petcoke, asphaltenes) from which(e.g. by gasification or reforming) the feed gas (e.g. sour syngasmixture) is obtained, mal-performance or deterioration in an upstreamunit (e.g. gasifier/reformer, water-gas shift unit, pressure swingadsorber or other separation device), or other process upsets.Variations in H₂S content can be monitored using standard H₂S-analyzers,as will be known to one of ordinary skill in the art. H₂S content may bemonitored at any suitable location. For example, the H₂S content of thesour gas stream may be monitored directly, by monitoring the content ofthis stream. Alternatively, it could be monitored indirectly, bymonitoring the H₂S content of the feed gas and/or H₂S-lean CO₂ productstream.

The term “sour”, as used herein (and as is used in the art), refers to agas or stream comprising H₂S. Likewise, the term “sweetened” or “sweet”refers to a gas or stream from which at least some of, and preferablysubstantially all or all of the H₂S has been removed.

The feed gas comprises, as noted above, at least CO₂, H₂S and H₂. Thefeed gas preferably comprises from about 10 to about 65 mole % CO₂, morepreferably from about 10 to about 45 mole % CO₂. The feed gas preferablycomprises up to about 3 mole %, or up to about 1.5 mole % H₂S, andpreferably comprises at least about 50 ppm H₂S. The feed gas preferablycomprises at least about 30 mole %, and more preferably at least about50 mole % H₂. The feed gas is preferably a gaseous mixture obtained fromgasification or reformation of a carbonaceous feedstock, and which mayhave been subjected to further processes such as, for example, awater-gas shift reaction (to convert some or all of the CO, present inthe initially produced crude syngas, to CO₂ and H₂). Preferably, thefeed gas is a sour syngas mixture (which, therefore, contains also atleast some CO in addition to said CO₂, H₂S and H₂). The feed gas may,for example, also contain: other carbonaceous species, such as CH₄;other sulfurous (i.e. sulfur containing) species, such as COS and CS₂;inerts, such as Ar and/or N₂; and/or water.

Where the feed gas contains also other sulfurous species (in addition toH₂S), it is preferred that these are dealt with in the method of thepresent invention in the same manner as H₂S. Thus, where for example astream is indicated herein as being enriched in, depleted in, lean in orfree of H₂S, said stream is preferably enriched in, depleted in, lean inor free of all other sulfurous species (where present) also; and wherereference is made herein to H₂S being adsorbed, removed or combustedthen preferably other sulfurous species (where present) are adsorbed,removed or combusted also. In addition, where reference is made hereinto maximum ppm or mole % of H₂S, preferably these represent also themaximum ppm or mole % of all sulfurous species (in total) in the gas orstream in question. Thus, for example, where the feed gas contains alsoother sulfurous species, the feed gas preferably comprises at most about3 mole %, and more preferably at most about 1.5 mole % of sulfurousspecies (in total).

The H₂-enriched product gas is enriched in H₂ relative to the feed gas(i.e. it has a higher mole % of H₂ than the feed gas). It is alsodepleted in H₂S and CO₂ relative to the feed gas (i.e. it has a lowermole % of H₂S and a lower mole % of CO₂ than the feed gas). It ispreferably free or at least substantially free of H₂S. For example, theH₂-enriched product gas preferably has an H₂S concentration of less thanabout 20 ppm, more preferably less than about 10 ppm, and mostpreferably less than about 5 ppm. It may also be free or at leastsubstantially free of CO₂. Where the feed gas contains also CO, theH₂-enriched product gas may be enriched in CO or depleted in CO (or,indeed, neither) relative to the feed gas, depending on the desired enduse of said product. It is generally preferred, however, that where thefeed stream contains more than minor amounts of CO then the H₂-enrichedproduct gas is enriched in CO as well as H₂. Thus, it is generallypreferred that it is only where the feed gas has a CO concentration ofabout 5 mole % or less, more preferably of about 2 mole % or less, andmost preferably of about 1 mole % or less that the H₂-enriched productgas is not enriched in CO relative to the feed gas.

Preferably, the H₂ recovery in the H₂-enriched product gas (i.e. thepercentage of the H₂ present in the feed gas that is recovered in theH₂-enriched product) is at least about 80%, more preferably at leastabout 85%, more preferably at least about 90%, and most preferably atleast about 95%. Where the feed stream contains CO and it is desiredthat the H₂-enriched product is enriched in CO as well as H₂, thecombined recovery of H₂ and CO in the H₂-enriched product (i.e. thepercentage of H₂ and CO (in combination) present in the feed gas that isrecovered in the H₂-enriched product) is preferably at least about 75%,more preferably at least about 80%, and most preferably at least about90%. The percentage recovery in the H₂-enriched product gas of acomponent or combination of components can be calculated from the molesof the component or components in question in the feed gas andH₂-enriched product gas. Thus, if for example the feed gas were tocontain 25 kmol/hr of H₂ and 25 kmol/hr of CO, and the H₂-enrichedproduct gas were to comprise 23 kmol/hr of H₂ and 20 kmol/hr of CO, inthis case 92% of the H₂ would be recovered in the H₂-enriched productstream and 86% of the H₂ and CO (in combination) would be recovered inthe H₂-enriched product stream.

Preferably, the H₂-enriched product gas comprises at least about 90 moleH₂ or a mixture of H₂ and CO, and is free or at least substantially freeof H₂S. The H₂-enriched product gas may, for example, comprise greaterthan about 90 mole % H₂, as may be the case where the H₂-enriched gas isintended for use as a fuel for combustion and expansion in, for example,a gas turbine to generate power. Alternatively, the H₂-enriched gas may,for example, comprise greater than about 99.99 mole % H₂, as for examplemay be the case where the H₂-enriched gas is intended for use, withoutrequiring further purification, for chemicals or refining applications.Alternatively still, the H₂-enriched gas may, for example, comprise atleast about 90 mole %, and more preferably 95 mole % of a mixture of H₂and CO, with a CO:H₂ ratio as desired for the product's intendedapplication, such as a CO:H₂ ratio between about 1:3 and about 3:1, andmore preferably from about 1:1 to about 1:2.5 (as, for example, may bedesired in Fischer-Tropsch process).

The sour gas comprises, as noted above, CO₂, H₂S and at least some H₂,although it is depleted in H₂ and enriched in H₂S and CO₂ relative tothe feed gas (i.e. has a lower mole % of H₂ and higher mole % of H₂S andCO₂ than the feed gas). Preferably, the sour gas contains at most about30 mole % H₂, and typically will contain at least about 5 mole % H₂.Preferably, the sour gas comprises at most about 6 mole %, and morepreferably at most about 3 mole % or at most about 1 mole % H₂S, andpreferably the sour gas comprises at least about 100 ppm and morepreferably at least about 0.5 mole % H₂S. Preferably, the sour gascomprises at least about 80 mole % CO₂. The sour gas may furthercomprise other carbonaceous species, such as CO and/or CH₄, and/or othersulfur containing species, such as COS and/or CS₂, as may have beenpresent in the feed gas. Where CO and/or CH₄ are present in sour gasstream, the stream preferably comprises at most about 15 mole % of CO,CH₄ or the combination of the two.

The or each stream of sweetened gas, obtained from processing the sourgas in the H₂S removal system to remove H₂S therefrom, is as noted abovedepleted in H₂S relative to the feed gas. As with the sour gas fromwhich it or they are formed, the or each stream of sweetened gas is alsoenriched in CO₂, and depleted in H₂, relative to the feed gas.Preferably, the or each stream of sweetened gas free or substantiallyfree of H₂S. Preferably, the H₂S removal system removes at least about90%, more preferably at least about 97%, and most preferably at leastabout 99% of the H₂S present in the sour gas being processed in saidsystem, such that the percentage of the H₂S present in the sour gas thatis recovered in the stream of sweetened gas or, where more than onestream is produced, in the streams in combination is preferably at mostabout 10%, more preferably at most about 3%, more preferably at mostabout 1% (the percentage recovery of H₂S likewise being calculable fromthe moles of H₂S present in the sour gas to be processed versus themoles of H₂S present in the stream or combination of streams ofsweetened gas). The stream of sour gas bypassing the H₂S removal systemis, self-evidently, not processed to remove H₂S therefrom.

The H₂S-lean, CO₂ product gas preferably has an H₂S concentration of atmost about 200 ppm, more preferably at most about 100 ppm. Preferably,the H₂S-lean, CO₂ product gas has an H₂ concentration of at most about 4mole %, more preferably at most about 1 mole %.

The feed gas is, in preferred embodiments, separated to form the streamof H₂-enriched product gas and stream of sour gas by pressure swingadsorption (PSA). The use of pressure swing adsorption to separate outthe H₂-enriched product provides for both capital and operating costsavings and reduced power consumption as compared to use of liquidsolvent absorption processes as used in the standard commercialarrangement (whereby, as described above, a liquid solvent absorptionprocess is used to separate a feed into separate H₂S, CO₂ and H₂streams, followed by treatment of the H₂S-rich stream in a Claus unit).

The PSA system in which the separation is carried out will comprise oneor more types of adsorbent that selectively adsorb CO₂ and H₂S (i.e.that adsorb CO₂ and H₂S preferentially to H₂). If other sulfurcontaining species, such as COS and/or CS₂, are present in the feed gasthen a PSA system is used which, preferably, comprises one or more typesof adsorbent that selectively adsorb these additional sulfur containingspecies also. If CO and/or other carbon containing species are alsopresent in the feed gas, then adsorbents that selectively adsorb some orall of these species may or may not be used, depending on the desiredcomposition of the H₂-enriched product gas. Exemplary adsorbents includecarbons, aluminas, silica gels and molecular sieves. For example, asingle layer of silica gel may be used if the product requirement is aH₂/CO mixture, a single layer of silica gel or a silica gel/carbon splitmay be used if the required product is gas turbine grade H₂, and asilica gel/carbon/5A zeolite split may be used if the required productis high purity H₂. A suitable type of silica gel for use as an adsorbentis, for example, the high purity silica gel (greater than 99% SiO₂)described in US-A1-2010/0011955, the disclosure of which is incorporatedherein by reference.

The system may comprise a plurality of adsorbent beds, as is known inthe art. For example, the system may comprise a plurality of beds, withthe PSA cycles of the individual beds being appropriately staggered sothat at any point in time there is always at least one bed undergoingadsorption and at least one bed undergoing regeneration, such that thesystem can continuously separate the stream fed to it. The system maycomprise beds arranged in series and/or in parallel. The PSA system maycomprise a single type of adsorbent, selective for all the componentsthat are to be selectively adsorbed by said system, or more than onetype of adsorbent which adsorbents in combination provide the desiredselective adsorption. Where more than one type of adsorbent is present,these may be intermixed and/or arranged in separate layers/zones of abed, or present in separate beds arranged in series, or arranged in anyother manner as appropriate and known in the art.

The PSA system may be operated in the same way as known PSA systems forseparating H₂ from CO₂ (also referred to herein as H₂-PSA systems), withall known cycle options appropriate to this technology area (e.g. cycleand step timings; use, order and operation of adsorption, equalization,repressurisation, depressurization and purge steps; and so forth). ThePSA cycle will, of course, typically include at least adsorption,blowdown/depressurisation and purge steps. During the adsorption stepthe feed gas is fed at super-atmospheric pressure to the bed(s)undergoing the adsorption step and CO₂, H₂S and any other species forwhich the adsorbent is selective are selectively adsorbed, at least aportion of the gas pushed through the bed(s) during this step formingall or at least a portion of the stream of H₂-enriched product gas.During the blowdown/depressurization and purge steps the pressure in thebed(s) is reduced and a purge gas passed through the bed(s) to desorbCO₂, H₂S and any other species adsorbed in the previous adsorption step,thereby regenerating the bed(s) in preparation for the next adsorptionstep, at least a portion of the gases obtained from the blowdown and/orpurge steps forming all or at least a portion of the stream of sour gas.Although, as noted above, the adsorbent used in the PSA system isselective for CO₂ and H₂S, due to the manner in which the PSA processoperates some H₂ will nevertheless also be present in the sour gas (forexample as a result of some H₂ also being adsorbed, being present in thevoid space of the bed(s), and/or being present in the gas(es) used topurge the bed(s)).

Suitable operating conditions for PSA systems are likewise known in theart. The adsorption step may, for example, be carried out by feeding thefeed gas to the PSA system at a pressure of about 1-10 MPa (10-100 bar)absolute and at a temperature in the range of about 10-60° C., in whichcase the H₂-enriched product gas will be obtained at about the samepressure. The H₂-enriched product gas may, if desired, be expanded toproduce power prior to said product gas being put to further use (e.g.in chemicals or refining applications).

The sour gas will typically be obtained at pressures about or slightlyabove atmospheric, i.e. about or slightly above 0.1 MPa (1 bar)absolute, but may for example also be obtained at pressures of up toabout 0.5 MPa (5 bar) absolute or at sub-atmospheric pressures of downto about 0.01 MPa (0.1 bar) absolute (in this latter case the PSA systembeing a vacuum pressure swing adsorption system). Higher pressures forthe blowdown and purge steps may also be employed if desired (althoughthe performance of the PSA system will decrease where the base pressureof the PSA is higher, due to the dynamic capacity of the PSA systembeing decreased, the gas obtained from the blowdown and purge steps willbe obtained at higher pressure, which may be beneficial wherecompression of these gases for further use is required). The gas usedfor purging can be preheated at least in part before use. If heating isused, then a typical temperature that the purge gas is raised to is inthe range of about 150° C. to about 300° C.

In a preferred embodiment, the method is carried out using a fossil fuelfired gasification system integrated with a PSA system that separatesthe sour syngas stream produced by the gasifier (optionally afterfurther process steps such as a water-gas shift reaction) to form thestream of H₂-enriched product gas and stream of sour gas.

The method may further comprise separating the stream of H₂S-lean, CO₂product gas to form an H₂S-lean, H₂-lean, CO₂ product and a gascomprising H₂. Typically, the gas comprising H₂ is enriched in H₂relative to the feed gas, and therefore constitutes a second H₂-enrichedgas (the H₂-enriched product gas being the “first” H₂-enriched gas).Preferably, the H₂S-lean, H₂-lean, CO₂ product comprises at least about98 mole %, more preferably at least about 99 mole %, more preferably atleast about 99.9 mole % CO₂. Preferably, the gas comprising H₂ (secondH₂-enriched gas) is at least about 60 mole %, more preferably at leastabout 70 mole % H₂. The gas comprising H₂ (second H₂-enriched gas) maybe used in any other process where it would be of value. For example,depending on its composition the gas could be: blended with theH₂-enriched product gas (i.e. the “first” H₂-enriched gas) obtained viaseparation of the feed gas; recycled back to the system used to separatethe feed gas (for example, where said system is a PSA system the gascomprising H₂ may be combined with the feed gas, separated in anadditional adsorption step to provide a further portion of theH₂-enriched product gas and sour gas, used as a rinse gas in a rinsestep of the PSA cycle, or used as a repressurisation gas in arepressurisation step of the PSA cycle); and/or used in one or moreadditional processes. The H₂S-lean, H₂-lean, CO₂ product may becompressed (or pumped) to sufficient pressure for sequestration or foruse in EOR applications.

The H₂S-lean, CO₂ product gas may, for example, be separated to form theH₂S-lean, H₂-lean, CO₂ product and gas comprising H₂ (second H₂-enrichedgas) by partial condensation or using membrane separation.

In the case of partial condensation, the H₂S-lean, CO₂ product gas iscooled and separated into a condensate and a vapour, for example usingone or more phase separators and/or distillation columns. The heaviercomponents, namely CO₂ and remaining H₂S, are concentrated in the liquidphase, which therefore forms the H₂S-lean, H₂-lean, CO₂ product, thegaseous phase forming the gas comprising H₂ (second H₂-enriched gas).Partial condensation systems that would be suitable for separating theH₂S-lean, CO₂ product gas are, for example, described inUS-A1-2008/0173585 and US-A1-2008/0173584, the disclosures of which areincorporated herein by reference.

Where partial condensation is used, it is also important that water andother components that may freeze out (e.g. NH₃ and trace levels of tars)are not present in the stream of H₂S-lean, CO₂ product gas introducedinto partial condensation system or are present only in sufficientlysmall amounts to avoid them freezing out and blocking the condensationsystem heat exchanger (which is used to cool the gas as necessary forsubsequent separation into condensate and vapour) or otherwise affectingthe performance of the condensation system. In order to remove water adrying system, such as a temperature swing adsorption (TSA) orabsorptive (e.g. gycol, glycerol) system, may be used at any pointupstream of the condensation system.

Where membrane separation is used, the H₂S-lean, CO₂ product gas may beseparated using one or more membranes having selective permeability(i.e. that are more permeable to one or more components of the stream tobe separated than they are to one or more other components of saidstream). For example, membranes may be used that are permeable to H₂ butlargely impermeable to CO₂ and/or vice versa, such as are described inJournal of Membrane Science 327 (2009) 18-31, “Polymeric membranes forthe hydrogen economy: Contemporary approaches and prospects for thefuture”, the disclosure of which is incorporated herein by reference.Where, for example, a membrane is used that is permeable to H₂ but is,in comparison, largely impermeable to CO₂ and H₂S, during the membraneseparation process the H₂S-lean, CO₂ product gas is introduced(typically at elevated pressure) into the membrane separation system andseparated by the membrane into the second H₂-enriched gas (obtained at alower pressure from the permeate side of the membrane) and the H₂S-lean,H₂-lean, CO₂ product (obtained at elevated pressure from the upstreamside of the membrane). A nitrogen ‘sweep’ stream may also be used toincrease the driving force for separation, allowing the stream ofH₂-enriched gas leaving the membrane separation system to be obtained ata higher pressure for the same membrane surface area. Membraneseparation technologies are well documented in the literature and can bebroadly classified as metallic, inorganics, porous carbons, organicpolymers, and hybrids or composites (see, for example, Membranes forHydrogen Separation, Nathan W. Ockwig and, Tina M. Nenoff, ChemicalReviews 2007 107 (10), 4078-4110, the disclosure of which isincorporated herein by reference). Polymer membranes constitute apreferred type of membrane for use in the present invention.

The H₂S removal system may be a system of any type suitable forprocessing the sour gas to obtain the desired stream(s) of sweetenedgas, and may comprise a single type of system or a combination of two ormore different types of systems.

In one embodiment, the H₂S removal system may, for example, comprise anadsorption system comprising one or more beds of adsorbent selective forH₂₅, the processing of sour gas in the H₂S removal system comprisingpassing sour gas through said beds of adsorbent to adsorb H₂S therefromand form said or one of said stream(s) of sweetened gas.

The bed or beds may comprise a single type of adsorbent or more than onetype of adsorbent selective for H₂S (i.e. that adsorb H₂S in preferenceto CO₂). Preferably the system also comprises one or more adsorbentsselective for any other sulfur containing species present in the sourgas (which adsorbents may be the same or different from the adsorbent(s)selective for H₂S, and may be present in the same or different beds ofthe system). The system may, for example, use adsorbent of anon-regenerable type, e.g. H₂S scavengers such as iron sponge or ZnO,which are disposed of and replaced once saturated with H₂S (although, incases where the sour gas comprises greater than about 100 ppm H₂S anynon-regenerable adsorbents are preferably only used as a final polishingstep of the H₂S removal process, the H₂S removal system thereforeincluding also a regenerable adsorbent system or another type of H₂Sremoval system that first removes the bulk of the H₂S prior to removalof remaining H₂S by the non-regenerable adsorbent). Use of method of thepresent invention in connection with such a system can reducecapital/operating costs by reducing the flow rate of sour gas that thebed(s) of regenerable adsorbent have to process and/or frequency withwhich the H₂S scavenger has to be replaced.

In one embodiment, the H₂S removal system may, for example, comprise asystem that converts H₂S to elemental sulfur, the processing of sour gasin the H₂S removal system comprising contacting sour gas with a reagent(e.g. one or more catalysts and/or reactants) to convert H₂S toelemental sulfur (which sulfur may then be removed by, for example, anysuitable sulfur handling processes as are known in the art) and formsaid or one of said stream(s) of sweetened gas. Preferably, the H₂Sremoval system comprises a catalyst that catalyses the conversion of H₂Sto elemental sulfur.

The system for converting H₂S to elemental sulfur may, for example, be asystem that converts the H₂S to elemental sulfur by a direct oxidationor redox process (i.e., LO-CAT, Sulfa-Treat). These processes are wellknown in the industry and usually operate in three sections comprising agas treating, a catalyst regeneration section, and a sulfur handlingsection. Use of such systems may be a preferred option where the sourgas stream typically comprises less than about 5%. Use of method of thepresent invention in connection with such a system can reduce costs byreducing operating costs associated with regenerating the catalyst (inthe catalyst regeneration section), and also reducing the amount ofsulfur that is removed thus reducing operating costs associated with thesulfur handling section.

Where the sour gas contains, in addition to H₂S, one or more othersulfur containing species, the method may further comprise treating aportion or all of the sour gas to be processed in the H₂S to elementalsulfur conversion system to convert one or more of said sulfurcontaining species to H₂S prior to said sour gas being processed in saidconversion system. This may, in particular, be preferred where a higherH₂S concentration is desirable for optimal performance of the conversionsystem in question. Alternatively or additionally, one or more other H₂Sand/or sulfur species containing gas streams, as may be availableon-site or be imported from off-site, may be blended with the sour gasto be processed in the conversion system, again to increase the overallH₂S concentration of said gas to be processed in the conversion system,where this may be desirable.

Other sulfur species that may be present in the sour gas include, inparticular, and as described above, COS and CS₂. A variety of processesfor converting such species to H₂S are known, and may suitably beemployed. For example, COS may be converted to H₂S and CO₂ in thepresence of alumina and/or titania catalysts via the hydrolysis reactionCOS+H₂O→+H₂S+CO₂. CS₂ may be reduced to produce H₂S via the reactionCS₂+2H₂→+2H₂S+C, which is generally favored at high temperatures and canproceed over a Co—Mo—Al catalyst. The aforementioned hydrolysis reactionis also favored at high temperatures.

In one embodiment, the H₂S removal system may, for example, comprise acombustion system, wherein the processing of sour gas in the H₂S removalsystem comprises combusting sour gas in the presence of O₂ to produceheat and a combustion effluent depleted in H₂S and H₂, relative to thefeed gas, and comprising CO₂, SO_(x) and H₂O, SO_(x) being removed fromsaid combustion effluent to form (from the resulting SO_(x)-depletedcombustion effluent) said or one of said stream(s) of sweetened gas. Useof method of the present invention in connection with such a system canreduce costs by reducing operating cost associated with the addition ofa trim fuel (i.e. natural gas) which may necessarily or desirably becombusted alongside the sour gas to support combustion of the latter (inparticular, where the latter is of low calorific value). The bypassingof the combustion system with part of the sour gas also allows forpotential further recovery of hydrogen still present in that part of thesour gas (all or substantially all of the hydrogen sent to thecombustion system typically being combusted to form water) which maylikewise be of economic benefit.

The combustion system is preferably an oxy-fuel combustion system,whereby the sour gas is combusted via oxy-fuel combustion. As usedherein, the term “oxy-fuel combustion” refers to combustion where theoxidant stream, that is mixed with the sour gas (constituting the fuelto be combusted) to provide the O₂ for combustion, comprises greaterthan 21 mole % oxygen. More preferably, the oxidant stream is at leastabout 90 mole % oxygen, and most preferably at least about 95 mole %oxygen. The oxidant stream may be oxygen enriched air, oxygen enrichedrecycled flue gas, or substantially pure or pure oxygen. Preferably allor at least substantially all of the H₂S, H₂ and any other combustiblecomponents present in the sour gas are combusted to form theircombustion products (SO_(x) and H₂O in the case of H₂S_(x) and H₂O inthe case of H₂). Preferably, therefore, the amount of O₂ provided by theoxidant stream is in excess of the stoichiometric amount theoreticallyrequired for complete combustion of all combustible components presentin the sour gas to be combusted.

In this embodiment, the method preferably further comprises passing thecombustion effluent through a heat exchanger to recover heat therefromvia indirect heat exchange. The recovered heat may be put to varioususes. For example, the recovered heat may be used to generate steam(which may, for example, be used in turn in a steam turbine to generatepower), supplied to other processes, and/or exchanged with other processstreams.

Preferably, SO_(x) is removed from said combustion effluent by coolingthe combustion effluent to condense out water and convert SO₃ tosulfuric acid (typically, this will be carried out in a heat exchangerseparate from any heat exchanger initially used to recover useful heatfrom the combustion effluent in the manner discussed above), andmaintaining the cooled combustion effluent at elevated pressure(s), inthe presence of O₂, water and optionally NO_(x), for a sufficient timeto convert SO₂ to sulfurous acid and/or SO₂ to sulfuric acid and NO_(x)to nitric acid.

This process by which SO_(x) is removed may, in particular, be a processas described in US-A1-2007/0178035, preferred features of this processbeing, therefore, as described in this document. In particular, at leastsubstantially all (and usually all) of the SO_(x) and the bulk, usuallyabout 90%, of any NO_(x) is preferably removed. The combustion effluentis usually produced at a pressure of from about 0.1 MPa (1 bar) to about0.7 MPa (7 bar), and more typically from about 0.1 MPa (1 bar) to about0.2 MPa (2 bar), depending at least in part on the pressure at which thesour gas stream is introduced into the combustion system, and may becompressed to the elevated pressure. The elevated pressure is usually atleast about 0.3 MPa (3 bar) and preferably from about 1 MPa (10 bar) toabout 5 MPa (50 bar). Contact time (or “hold-up”) between the gaseouscomponents and the liquid water after elevation of the pressure affectsthe degree of conversion of SO₂ to H₂SO₄ and NO_(x) to HNO₃, a total“hold-up” time of no more than 60 seconds usually being sufficient formaximum conversion of SO₂/NO_(x). Counter current gas/liquid contactdevices such as columns or scrub towers allow intimate mixing of waterwith the gaseous components for continuous removal of SO₂ and NO_(x),and thus constitute suitable devices for providing the required contacttime for the conversion(s). The O₂ required for the conversions may beadded although an amount of O₂ may be present in the combustioneffluent, for example where a stoichiometric excess of O₂ was usedduring combustion. Water is present in the combustion effluent as one ofthe combustion products, but further water may be added if required.Likewise, NO_(x) may already be present in the combustion effluent,and/or may be added as required.

In one embodiment, the H₂S removal system may, for example, compriseboth a combustion system and a system that converts H₂S to elementalsulfur via reaction with SO₂, sulfuric acid and/or sulfurous acid. Thesour gas to be processed in the H₂S removal system is, in this case,divided into two streams, and said processing comprises:

contacting, in the H₂S to elemental sulfur system, a stream of sour gaswith the SO₂, sulfuric acid and/or sulfurous acid to convert H₂S toelemental sulfur (which sulfur may then be removed by, for example, anysuitable sulfur handling processes as are known in the art) and formsaid stream or one of said stream(s) of sweetened gas; and

combusting, in the combustion system, another stream of sour gas in thepresence of O₂ to produce heat and a combustion effluent depleted in H₂Sand H₂) relative to the feed gas, and comprising CO₂, SO_(x) and H₂O,and: (i) introducing at least a portion of the combustion effluent, oran SO₂-enriched stream separated from the combustion effluent, into theH₂S to elemental sulfur conversion system to provide at least a portionof said SO₂ for the reaction with H₂S; and/or (ii) converting SO_(x) inthe combustion effluent to sulfuric and/or sulfurous acid, andintroducing at least a portion of said acid into the H₂S to elementalsulfur conversion system to provide at least a portion of said acid forthe reaction with H₂S.

The method according to this embodiment therefore has the furtheradvantage, over the method described in US-A1-2007/0178035, that atleast a portion of the SO_(x) formed from combustion of H₂S in thecombustion system is disposed of either by conversion into elementalsulfur rather than by conversion to sulfuric acid, or by at least aportion of the sulfuric and/or sulfurous acid that is formed from theSO_(x) being further converted to elemental sulfur.

As described above in connection with other embodiments where the H₂Sremoval system comprises an H₂S to elemental sulfur conversion system,where the sour gas contains in addition to H₂S one or more other sulfurcontaining species the method may further comprise treating a portion orall of said stream of sour gas to be processed in said conversion systemto convert one or more of said sulfur containing species to H₂S prior tosaid stream being processed in the conversion system. Alternatively oradditionally, one or more other H₂S and/or sulfur species containing gasstreams, as may be available on-site or be imported from off-site, maybe blended with the sour gas stream to be processed in the conversionsystem, again to increase the overall H₂S concentration of said gas tobe processed in the conversion system.

As described above, in connection with other embodiments where the H₂Sremoval system comprises a combustion system, the combustion system maypreferably be an oxy-fuel combustion system, whereby the sour gas iscombusted via oxy-fuel combustion. The method may preferably furthercomprise passing the combustion effluent through a heat exchanger torecover heat therefrom via indirect heat exchange. The recovered heatmay be used to generate steam, supplied to other processes, and/orexchanged with other process streams. The recovered heat may, forexample, be used to supply some or all of the thermal load that may benecessary for optimal conversion of H₂S in the H₂S to elemental sulfurconversion system and/or for optimal prior treatment of the sour gasfeed to said conversion system to convert additional sulfur species toH₂S (where such prior treatment takes place).

Where the H₂S to elemental sulfur system converts H₂S to elementalsulfur via reaction with SO₂, and a portion of the combustion effluentis introduced into said conversion system to provide at least a portionof said SO₂ for reaction with H₂S, the combustion effluent may bedivided into at least two thereof, one of which is introduced into theconversion system to provide at least a portion of said SO₂ for thereaction with H₂S, and the other of which forms a second of said streamsof sweetened gas.

Where the H₂S to elemental sulfur system converts H₂S to elementalsulfur via reaction with SO₂, the combustion effluent is separated toform an SO₂-enriched stream (i.e. stream enriched in SO₂ relative to thecombustion effluent) and an SO₂-depleted stream (i.e. a stream depletedin SO₂ relative to the combustion effluent), and the SO₂-enriched streamis introduced into said conversion system to provide at least a portionof said SO₂ for reaction with H₂S, the SO₂-depleted stream may form asecond of said streams of sweetened gas. The combustion effluent may beseparated to form an SO₂-enriched stream and an SO₂-depleted stream viaany suitable means. For example, the combustion effluent may beseparated using suitable adsorbents (such as for example described inU.S. Pat. No. 5,248,321, the disclosure of which is incorporated hereinby reference) or via distillation (for example using a system asdescribed in EP-A-0798032, the disclosure of which is incorporatedherein by reference).

By introducing into the H₂S to elemental sulfur conversion system aseparated SO₂-enriched stream, or only that amount of the combustioneffluent required to provide the necessary amount of SO₂ for reactionwith H₂S, and taking the SO₂-depleted stream or the remainder of thecombustion effluent as an additional stream of sweetened gas, the amountof sour gas to be combusted in the combustion system relative to theamount treated in the conversion system can be increased withoutaffecting the reaction stoichiometry in the conversion system. This, inturn, may allow additional useful heat to be generated by and recoveredfrom the combustion reaction. However, in this case care should be takento ensure that the amount of combustion effluent, or amount of anyresidual SO_(x) in the SO₂-depleted stream, taken as an additionalstream of sweetened gas is not such that the SO_(x) content of theH₂S-lean, CO₂ product gas exceeds acceptable limits. Where, for example,the combustion effluent is being divided and a portion thereof taken asan additional stream of sweetened gas, it is therefore preferable thatboth the division of sour gas between the stream sent to the conversionsystem and the stream sent to the combustion system, and the division ofthe combustion effluent between being sent to the conversion system andbeing taken as an additional sweetened gas, are adjusted as necessaryresponsive to changes in the H₂S content of the sour gas, such that boththe reaction stoichiometry within the conversion system and the SO_(x)content of the H₂S-lean, CO₂ product gas are maintained within desiredlimits.

Where the H₂S to elemental sulfur system converts H₂S to elementalsulfur via reaction with SO₂, the H₂S to elemental sulfur systempreferably comprises a catalyst that catalyses the conversion of H₂S toelemental sulfur via reaction with SO₂. Suitable catalysts include, forexample, catalysts as used in the catalytic step(s) of the Clausprocess.

Where the H₂S to elemental sulfur conversion system converts H₂S toelemental sulfur via reaction with sulfuric and/or sulfurous acid,SO_(x) in the combustion effluent is converted to sulfuric and/orsulfurous acid, and at least a portion of said acid is introduced intothe H₂S to elemental sulfur conversion system to provide at least aportion of said acid for the reaction with H₂S, the SO_(x)-depletedcombustion effluent (obtained following removal of the acid) may form asecond of said streams of sweetened gas. Prior to being introduced inthe H₂S to elemental sulfur conversion system, the sulfuric and/orsulfurous acid stream may be heated to drive off excess water, therebyconcentrating the acid before it is added to the conversion system. Suchevaporation of water is preferably carried out at atmospheric pressureor under vacuum.

The SO_(x) in the combustion effluent may be converted to sulfuric acidor sulfuric and sulfurous acid by cooling the combustion effluent tocondense out water and convert SO₃ to sulfuric acid, and maintaining thecooled combustion effluent at elevated pressure(s), in the presence ofO₂, water and optionally NO_(x), for a sufficient time to convert SO₂ tosulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.The process by which SO_(x) is converted to sulfuric acid may, inparticular, be a process as described in US-A1-2007/0178035, preferredfeatures of this process being, therefore, as described in this documentand/or as described above in relation to other embodiments of thepresent invention where SO_(x) in the combustion effluent is convertedto sulfuric acid.

The conversion of H₂S to elemental sulfur via reaction with sulfuricacid may proceed according to the reaction 3H₂S+H₂SO₄→4S+4H₂O, whereinaqueous H₂SO₄ is reacted with gaseous H₂S. Similarly, the conversion ofH₂S to elemental sulfur via reaction with sulfurous acid may proceedaccording to the reaction 2H₂S+H₂SO₃→3S+3H₂O, wherein aqueous H₂SO₃ isreacted with gaseous H₂S. Further details regarding the reaction betweenH₂S and sulfuric acid are, for example, given in: Reactions betweenHydrogen Sulfide and Sulfuric Acid: A Novel Process for Sulfur Removaland Recovery, Qinglin Zhang, Ivo G. Dalla Lana, Karl T. Chuang,^(†) and,Hui Wang, Industrial & Engineering Chemistry Research 2000 39 (7),2505-2509; Kinetics of Reaction between Hydrogen Sulfide and SulfurDioxide in Sulfuric Acid Solutions, Ind. Eng. Chem. Res. 2002, 41,4707-4713; Thermodynamics and Stoichiometry of Reactions betweenHydrogen Sulfide and Concentration Sulfuric Acid, The Canadian Journalof Chemical Engineering, Volume 81, February 2003; and Mass-TransferCharacteristics for Gas-Liquid Reaction of H₂S and Sulfuric Acid in aPacked Column Ind. Eng. Chem. Res. 2004, 43, 5846-5853; the disclosuresof which are incorporated herein by reference.

In any of the above embodiments, the method may further compriseprocessing one or more additional H₂S containing streams in the H₂Sremoval system alongside said part of said stream of sour gas to beprocessed in the H₂S removal system. These additional streams may bederived from processes within the plant, or may be obtained fromoff-site. For example, where the feed gas is separated by pressure swingadsorption, the PSA system may produce two separate streams of sour gas(of, for example, different composition), with one of said streams beingdivided into two parts, one of which is sent to the H₂S removal systemand the other of which bypasses said system (as described above), andthe other of said streams being processed, in its entirety, in the H₂Sremoval system (alongside said part of said first mentioned stream).Where the two streams of sour gas are of different composition (as maybe the case where, for example, one is formed from gas obtained duringthe blowdown step of the PSA process and the other is formed from gasobtained during the purge step), it may in particular be preferable toprocess all of the stream of higher H₂S content (e.g. formed from theblowdown step) in the H₂S removal system, and divide the stream of lowerH₂S content (e.g. formed from the purge step) into one part forprocessing in the H₂S removal system and another part for bypassing saidsystem.

Apparatus of the present invention are suitable for carrying out theabove described method. The apparatus comprises:

a pressure swing adsorption (PSA) system for separating the feed gas toform a stream of H₂-enriched product gas and a stream of sour gas, thesour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ andenriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form oneor more streams of sweetened gas, depleted in H₂S and enriched in CO₂relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂Sremoval system and bypassing the H₂S removal system with another part ofsaid sour gas;

a valve system for adjustably controlling the division of said sour gasbetween being sent to the H₂S removal system and bypassing said system;and

conduit means for withdrawing one or more streams of sweetened gas fromthe H₂S removal system and combining said stream(s) with the sour gasbypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

The apparatus may further comprise a separation system for receiving theH₂S-lean, CO₂ product gas and separating said gas to form an H₂S-lean,H₂-lean, CO₂ product and a gas comprising H₂ (preferably, a secondH₂-enriched gas).

In one embodiment:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor converting H₂S to elemental sulfur via reaction with SO₂, and (iii)conduit means for transferring at least a portion of the combustioneffluent from the combustion system to the H₂S to elemental sulfurconversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the combustion system formed from a portion of thecombustion effluent.

In another embodiment:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor receiving and separating the combustion effluent to form anSO₂-enriched stream and an SO₂-depleted stream (iii) a system forconverting H₂S to elemental sulfur via reaction with SO₂, and (iv)conduit means for transferring the SO₂-enriched stream from the systemfor separating the combustion effluent to the H₂S to elemental sulfurconversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the system for separating the combustion effluentformed from the SO₂-depleted stream.

In another embodiment:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor receiving combustion effluent from the combustion system, convertingSO_(x) in said effluent to sulfuric acid and/or sulfurous acid, andseparating said acid from the effluent to form an SO_(x)-depletedcombustion effluent, (iii) a system for converting H₂S to elementalsulfur via reaction with sulfuric and/or sulfurous acid, and (iv)conduit means for transferring sulfuric and/or sulfurous acid from theSO_(x) to acid conversion system to the H₂S to elemental sulfurconversion system to provide sulfuric and/or sulfurous acid for reactionwith H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the SO_(x) to sulfuric and/or sulfurous acidconversion system formed from the SO_(x)-depleted effluent.

The system for converting SO_(x) to sulfuric and/or sulfurous acid may,for example, comprise a cooling system for cooling the combustioneffluent to condense out water and convert SO₃ to sulfuric acid, acompressor for elevating the pressure of the cooled combustion effluent,and a counter current gas/liquid contact device for washing the cooledcombustion effluent with water at elevated pressure(s), in the presenceof O₂ and optionally NO_(x), for a sufficient time to convert SO₂ tosulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.

Further preferred features and embodiments of the apparatus according tothe invention will be apparent from the foregoing description ofpreferred features and embodiments of the method of the invention.

Aspects of the invention include:

#1. A method for treating a feed gas, comprising CO₂, H₂S and H₂, toproduce an H₂-enriched product and an H₂S-lean, CO₂ product, the methodcomprising:

separating the feed gas to form a stream of H₂-enriched product gas anda stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂ butbeing depleted in H₂ and enriched in H₂S and CO₂ relative to the feedgas;

dividing the stream of sour gas into two parts;

processing one part of said stream of sour gas in an H₂S removal systemto form one or more streams of sweetened gas, depleted in H₂S andenriched in CO₂ relative to the feed gas;

bypassing the H₂S removal system with the other part of said stream ofsour gas; and

combining said stream(s) of sweetened gas with said sour gas bypassingthe H₂S removal system to form a stream of H₂S-lean, CO₂ product gas;

wherein the division of the sour gas between being sent to and processedin the H₂S removal system and bypassing said system is adjustedresponsive to changes in the H₂S content of the sour gas, such that theproportion of the sour gas processed in the H₂S removal system, ascompared to bypassing said system, is increased if the H₂S content risesand decreased if the H₂S content drops.

#2. A method according to #1, wherein the feed gas has an H₂Sconcentration of from about 50 ppm to about 3 mole %.

#3. A method according to #1 or #2, wherein the feed gas is a soursyngas mixture, comprising CO₂, H₂S, H₂ and CO, obtained from gasifyingor reforming carbonaceous feedstock.

#4. A method according to any of #1 to #3, wherein the H₂-enrichedproduct gas comprises at least about 90 mole % H₂ or a mixture of H₂ andCO, and is free or substantially free of H₂S.

#5. A method according to any of #1 to #4, wherein the sour gascomprises less than about 6 mole % H₂S.

#6. A method according to any of #1 or #5, wherein the or each stream ofsweetened gas is free or substantially free of H₂S.

#7. A method according to any of #1 to #6, wherein the H₂S-lean, CO₂product gas contains less than 200 ppm H₂S.

#8. A method according to any of #1 to #7, wherein the feed gas isseparated by pressure swing adsorption.

#9. A method according to any of #1 to #8, wherein the method furthercomprises separating the stream of H₂S-lean, CO₂ product gas to form anH₂S-lean, H₂-lean, CO₂ product and a second H₂-enriched gas.

#10. A method according to #9, wherein the H₂S-lean, CO₂ product gas isseparated by partial condensation or membrane separation.

#11. A method according to any of #1 to #10, wherein the H₂S removalsystem comprises an adsorption system comprising one or more beds ofadsorbent selective for H₂S, and the processing of sour gas in the H₂Sremoval system comprises passing sour gas through said beds of adsorbentto adsorb H₂S therefrom and form said or one of said stream(s) ofsweetened gas.#12. A method according to any of #1 to #11, wherein the H₂S removalsystem comprises a system for converting H₂S to elemental sulfur, theprocessing of sour gas in the H₂S removal system comprising contactingsour gas with a reagent to convert H₂S to elemental sulfur and form saidor one of said stream(s) of sweetened gas.#13. A method according to any of #1 to #12, wherein the H₂S removalsystem comprises a combustion system, and the processing of sour gas inthe H₂S removal system comprises combusting sour gas in the presence ofO₂ to produce heat and a combustion effluent depleted in H₂S and H₂ andcomprising CO₂, SO_(x) and H₂O, SO_(x) being removed from saidcombustion effluent to form said or one of said stream(s) of sweetenedgas.#14. A method according to #13, wherein SO_(x) is removed from saidcombustion effluent by cooling the combustion effluent to condense outwater and convert SO₃ to sulfuric acid, and maintaining the cooledcombustion effluent at elevated pressure(s), in the presence of O₂,water and optionally NO_(x), for a sufficient time to convert SO₂ tosulfurous acid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.#15. A method according to any of #1 to #10, wherein the H₂S removalsystem comprises both a combustion system and a system for convertingH₂S to elemental sulfur via reaction with SO₂, sulfuric acid and/orsulfurous acid, and wherein the sour gas to be process in the H₂Sremoval system is divided into two streams, said processing comprising:

contacting, in the H₂S to elemental sulfur conversion system, a streamof sour gas with SO₂, sulfuric acid and/or sulfurous acid to convert H₂Sto elemental sulfur and form said stream or one of said stream(s) ofsweetened gas; and

combusting, in the combustion system, another stream of sour gas in thepresence of O₂ to produce heat and a combustion effluent depleted in H₂Sand H₂ and comprising CO₂, SO_(x) and H₂O, and: (i) introducing at leasta portion of the combustion effluent, or an SO₂ enriched streamseparated from the combustion effluent, into the H₂S to elemental sulfurconversion system to provide at least a portion of said SO₂ for thereaction with H₂S; and/or (ii) converting SO_(x) in the combustioneffluent to sulfuric and/or sulfurous acid, and introducing at least aportion of said acid into the H₂S to elemental sulfur conversion systemto provide at least a portion of said acid for the reaction with H₂S.

#16. A method according to #15, wherein the H₂S to elemental sulfurconversion system converts H₂S to elemental sulfur via reaction withSO₂, and at least a portion of the combustion effluent, or an SO₂enriched stream separated from the combustion effluent, is introducedinto said conversion system to provide at least a portion of said SO₂for the reaction with H₂S.#17. A method according to #16, wherein the combustion effluent isdivided into two streams thereof, one of which is introduced into saidconversion system to provide at least a portion of said SO₂ for thereaction with H₂S, and the other of which forms a second of said streamsof sweetened gas.#18. A method according to #16, wherein the combustion effluent isseparated to form an SO₂-enriched stream and an SO₂-depleted stream, theSO₂-enriched stream is introduced into said conversion system to provideat least a portion of said SO₂ for the reaction with H₂S, and theSO₂-depleted stream forms a second of said streams of sweetened gas#19. A method according to #15, wherein the H₂S to elemental sulfurconversion system converts H₂S to elemental sulfur via reaction withsulfuric and/or sulfurous acid, SO_(x) in the combustion effluent isconverted to sulfuric and/or sulfurous acid, and at least a portion ofsaid acid is introduced into said conversion system to provide at leasta portion of said acid for the reaction with H₂S.#20. A method according to #19, wherein SO_(x) in the combustioneffluent is converted to sulfuric or sulfuric and sulfurous acid bycooling the combustion effluent to condense out water and convert SO₃ tosulfuric acid, and maintaining the cooled combustion effluent atelevated pressure(s) in the presence of O₂, water and optionally NO_(x),for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ tosulfuric acid and NO_(x) to nitric acid.#21. A method according to #19 or #20, wherein the SO_(x)-depletedcombustion effluent forms a second of said streams of sweetened gas.#22. A method according to any of #12 or #15 to #21, wherein the sourgas contains, in addition to H₂S, one or more other sulfur containingspecies, and wherein the method further comprises treating a portion orall of said sour gas to be processed in the H₂S to elemental sulfurconversion system to convert one or more of said sulfur containingspecies to H₂S prior to said sour gas being processed in said conversionsystem.#23. A method according to any of #13 to #22, wherein the combustionsystem is an oxy-fuel combustion system.#24. A method according to any of #13 to #23, wherein the method furthercomprises passing the combustion effluent through a heat exchanger torecover heat therefrom via indirect heat exchange.#25. Apparatus for treating a feed gas, comprising CO₂, H₂S and H₂, toproduce an H₂-enriched product gas and an H₂S-lean, CO₂ product gas, theapparatus comprising:

a pressure swing adsorption (PSA) system for separating the feed gas toform a stream of H₂-enriched product gas and a stream of sour gas, thesour gas comprising CO₂, H₂S and H₂ but being depleted in H₂ andenriched in H₂S and CO₂ relative to the feed gas;

an H₂S removal system for processing a part of the sour gas to form oneor more streams of sweetened gas, depleted in H₂S and enriched in CO₂relative to the feed gas;

conduit means for transferring a part of said sour gas into the H₂Sremoval system and bypassing the H₂S removal system with another part ofsaid sour gas;

a valve system for adjustably controlling the division of said sour gasbetween being sent to the H₂S removal system and bypassing said system;and

conduit means for withdrawing one or more streams of sweetened gas fromthe H₂S removal system and combining said stream(s) with the sour gasbypassing the H₂S removal system to form H₂S-lean, CO₂ product gas.

#26. An apparatus according to #25, wherein the apparatus furthercomprises a separation system for receiving the H₂S-lean, CO₂ productgas and separating said gas to form an H₂S-lean, H₂-lean, CO₂ productand a second H₂-enriched gas.

#27. An apparatus according to #25 or #26, wherein:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor converting H₂S to elemental sulfur via reaction with SO₂, and (iii)conduit means for transferring at least a portion of the combustioneffluent from the combustion system to the H₂S to elemental sulfurconversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the combustion system formed from a portion of thecombustion effluent.

#28. An apparatus according to #25 or #26, wherein:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor receiving and separating the combustion effluent to form anSO₂-enriched stream and an SO₂-depleted stream (iii) a system forconverting H₂S to elemental sulfur via reaction with SO₂, and (iv)conduit means for transferring the SO₂-enriched stream from the systemfor separating the combustion effluent to the H₂S to elemental sulfurconversion system to provide SO₂ for reaction with H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the system for separating the combustion effluentformed from the SO₂-depleted stream.

#29. An apparatus according to #25 or #26, wherein:

the H₂S removal system comprises (i) a combustion system, for combustingsour gas in the presence of O₂ to produce heat and a combustion effluentdepleted in H₂S and H₂ and comprising CO₂, SO_(x) and H₂O, (ii) a systemfor receiving combustion effluent from the combustion system, convertingSO_(x) in said effluent to sulfuric and/or sulfurous acid, andseparating said acid from the effluent to form a SO_(x)-depletedcombustion effluent, (iii) a system for converting H₂S to elementalsulfur via reaction with sulfuric and/or sulfurous acid, and (iv)conduit means for transferring sulfuric acid and/or sulfurous acid fromthe SO_(x) to acid conversion system to the H₂S to elemental sulfurconversion system to provide sulfuric and/or sulfurous acid for reactionwith H₂S;

the conduit means for transferring a part of the sour gas into the H₂Sremoval system transfer a stream of sour gas into the combustion systemand a stream of sour gas into the H₂S to elemental sulfur conversionsystem; and

the conduit means for withdrawing one or more streams of sweetened gasfrom the H₂S removal system withdraw a stream of sweetened gas from theH₂S to elemental sulfur conversion system and, optionally, a stream ofsweetened gas from the SO_(x) to sulfuric and/or sulfurous acidconversion system formed from the SOx-depleted combustion effluent.

#30. An apparatus according to #29, wherein the system for convertingSO_(x) to sulfuric and/or sulfurous acid comprises a cooling system forcooling the combustion effluent to condense out water and convert SO₃ tosulfuric acid, a compressor for elevating the pressure of the cooledcombustion effluent, and a counter current gas/liquid contact device forwashing the cooled combustion effluent with water at elevatedpressure(s), in the presence of O₂ and optionally NO_(x), for asufficient time to convert SO₂ to sulfurous acid and/or SO₂ to sulfuricacid and NO_(x) to nitric acid.

Solely by way of example, certain embodiments of the invention will nowbe described with reference to the accompanying drawings.

Referring to FIG. 1, sour syngas stream 10, comprising H₂, CO, CO₂ andH₂S, is fed into PSA system 12, which separates the sour syngas bypressure swing adsorption into a high pressure stream, 14, ofH₂-enriched product gas and a low pressure stream, 16, of sour gas. Thesour gas also comprises H₂, CO, CO₂ and H₂S, but is enriched in CO₂ andH₂S and depleted in H₂ relative to the sour syngas. The H₂-enrichedproduct stream 14 may be expanded in optional expander 32, prior to, forexample, being sent as fuel to a gas turbine to generate power (as, forexample, where the H₂-enriched product comprises gas turbine fuel gradepurity H₂) or exported for chemicals or refining applications (as, forexample, where H₂-enriched gas comprises high purity, e.g. 99.99 mole %or higher, H₂ product or a high purity syngas comprising a desired H₂/COratio).

Sour gas stream 16 is divided into two further streams, 18 and 24(which, therefore, remain of the same composition as stream 16). Thedivision of the sour gas between streams 18 and 24 is adjustable, aswill be described below in further detail.

Sour gas stream 18 is fed into H₂S removal system 20, which processesthe stream to selectively remove all or substantially all the H₂Stherefrom, thereby forming stream 22 of sweetened gas which is devoid oralmost devoid of H₂S. The H₂S removal system may employ any suitablemeans of H₂S removal, including (but not limited to) adsorption,conversion to elemental sulfur, and/or combustion. The operation of twoexemplary H₂S removal systems will be described in further detail below,with reference to FIGS. 2 and 3. Sour gas stream 24 bypasses the H₂Sremoval system and is combined with sweetened gas stream 22 to form aH₂S-lean, CO₂ product gas. In the depicted embodiment streams 22 and 24are combined to form stream 26 of H₂S-lean, CO₂ product gas, whichstream is then compressed in compressor 28 prior to, optionally, beingfed to a further separation system. Equally, however, streams 22 and 24could be combined within compressor 28 to form the H₂S-lean, CO₂ productgas, or could be separately compressed and combined subsequently to formthe H₂S-lean, CO₂ product gas.

The division of the sour gas between streams 18 and 24 is adjustable, sothat it can be changed responsive to changes in the H₂S content of thesour gas. In this way, should the H₂S content of stream 16 rise, forexample due to the H₂S content of sour syngas stream 10 rising as aresult of a change in gasifier/reformer feedstock, the flow rate ofstream 18 can be increased and the flow rate of stream 24 decreased inorder to keep the H₂S content of the H₂S-lean, CO₂ product gas at orbelow a desired maximum content as dictated by the emissions and/or CO₂product specifications that the process is to meet. Likewise, should theH₂S content of stream 16 drop, the flow rate of stream 18 may be reducedand flow rate of stream 24 increased, up to a level at which the desiredmaximum H₂S content of the H₂S-lean, CO₂ product gas is still notexceeded, thereby conserving resources and/or reducing costs associatedwith the H₂S removal process.

As noted above, stream 26 of H₂S-lean, CO₂ product gas may, optionally,be compressed in compressor 28 and then fed to a further separationsystem. In the embodiment depicted in FIG. 1, the further separationsystem is a membrane separation system 30 comprising one or moremembranes that are permeable to H₂ but relatively impermeable to CO₂,but other types of system, such as for example a partial condensationsystem, could equally be used. The compressed H₂S-lean, CO₂ product gasis separated in the membrane separation system 30 into a stream 34 ofH₂-enriched gas, obtained at lower pressure from the permeate side ofthe membrane(s), and a stream 36 of H₂S-lean, H₂-lean CO₂ product gasobtained from the upstream side of the membrane(s). Optionally, an N₂‘sweep’ stream 38 is also used to increase the driving force forseparation, allowing stream 34 of second H₂-enriched gas leaving themembrane separation system to be obtained at a higher pressure with thesame membrane surface area. The second stream 34 of H₂-enriched gas maybe blended with stream 14 of H₂-enriched product gas, recycled to PSAsystem 10 (for example by being added to sour syngas stream 10 or bybeing used in a rinse or repressurisation step of the PSA cycle), orused in another process. The H₂S-lean, H₂-lean CO₂ product stream may becompressed in compressor 40 prior to being piped for geological storageor EOR.

In the embodiment depicted in FIG. 1, sour syngas stream 10 may forexample comprise about 57% H₂, 3% CO, 40% CO₂, and 100 ppm H₂S (allpercentages being mole %) and be introduced into PSA system at 1.2 to 6MPa (12 at 60 bar) absolute. The H₂-enriched product stream 14 maycomprise 95% H₂ and 5% CO and be obtained at the same or about the samepressure as the sour syngas feed to the PSA system (i.e. subject to anyunavoidable pressure drop associated with flow through the adsorbentpacked bed), and the sour gas streams 16 may comprise about 93% CO₂,6.6% H₂, 0.4% CO, and 233 ppm H₂S and be obtained at 1 bar absolute. Thestream of sweetened gas produced by the H₂S removal system (for examplecomprising a catalytic system for converting H₂S to elemental sulfur,e.g. LO-CAT, followed by a ZnO bed for final polishing) may compriseabout 6.6% H₂, 0.4% CO, 93% CO₂, 2 ppm H₂S. The H₂S-lean, CO₂ productstream 26 may comprise about 6.6% H₂, 0.4% CO₃ 93% CO₂ and 94 ppm H₂S.The second H₂-enriched gas may comprise 100% H₂ or (if an N₂ sweep isused) H₂/N₂. The H₂S-lean, H₂-lean CO₂ product stream 36 may compriseabout 96% CO₂, 4% CO and 98 ppm H₂S, and may be compressed to a pressureof 12 MPa (120 bar) absolute.

Referring to FIG. 2, in one exemplary embodiment the H₂S removal system20 comprises both an oxy-fuel combustion system 50 and an H₂S toelemental sulfur conversion system 52 comprising a catalyst thatcatalyses the conversion of H₂S to elemental sulfur via reaction withSO₂.

In the depicted embodiment, sour gas stream 18 is divided into streams54 and 56 but, equally, one or both of streams 54 and 56 could bedivided from stream 16 at the same time as or before stream 24. Stream54 is introduced into oxy-fuel combustion system 50 and combusted in thepresence of oxygen, provided by high purity oxygen stream 58, so as tocombust all or substantially all of the H₂, CO and H₂S present in thestream, thereby producing a combustion effluent 62 comprising CO₂,SO_(x) and H₂O. Optionally, additional fuel may also be supplied to andcombusted in the oxy-fuel combustion system 50, as indicated by stream60. The combustion effluent 62 is then passed to heat exchanger 64 torecover heat therefrom via indirect heat exchange.

Stream 56 of sour gas is introduced into the H₂S to elemental sulfurconversion system 52 where all or substantially all of the H₂S in thestream is reacted with SO₂ over the catalyst to produce elemental sulfurand H₂O (via the reaction 2H₂S+SO₂→+⅜S₈+2H₂O) and form stream 22 ofsweetened gas. The sulfur is removed as stream 68 via a sulfur handlingprocess within the conversion system. The SO₂ required for this reactionis supplied by feeding at least a portion 66 of the combustion effluent62 into the conversion system, the amount of combustion effluent fedinto the conversion system preferably being such as to provide an amountof SO₂ sufficient for, but not significantly in excess of, thestoichiometric amount required for reaction with H₂S. The heat requiredfor optimal conversion of H₂S to sulfur may be supplied by the heatrecovered from the combustion effluent in heat exchanger 64.Alternatively or additionally, the heat recovered from the combustioneffluent in heat exchanger 64 may be put to other uses, such as forexample heating stream 14 of H₂-enriched product gas prior to saidstream being expanded in optional expander 32.

Heat exchanger 64, although depicted as a single unit, could compriseone or more heat exchangers in series or parallel. The recovery of heatfrom stream 62 in heat exchanger 64 could, for example be via indirectheat transfer with any or all of streams 54, 58, 60, 56, and 14 bypassing said stream(s) through heat exchanger 64 also. Alternatively, aseparate a heat transfer fluid (e.g. steam), could be used that iscirculated through heat exchanger 64 and separate heat exchangers (notshown) associated with any or all of streams 54, 58, 60, 56, and 14 toachieve indirect heat transfer with these streams. A separate heattransfer fluid (not shown) heated by stream 62 in heat exchanger 64could also, for example, be used to heat the catalyst beds of conversionsystem 52.

The stream 22 of sweetened gas obtained from conversion system 52 isthen combined with stream 24 of sour gas to form the H₂S-lean, CO₂product, as described above with reference to FIG. 1. Water present inthe sweetened gas can be removed prior to or after combining the streamwith stream 24 of sour gas. For example, water may be removed duringcompression of the stream(s) in compressor 28. A further portion of thecombustion effluent 62 may optionally also be taken as a second, SO_(x)containing, stream 70 of sweetened gas. This second stream of sweetenedgas may be combined with the stream of sweetened gas from conversionsystem 52 as shown in FIG. 2, or the two streams of sweetened gas may beseparately added to stream 24 of sour gas to form the H₂S-lean, CO₂product. Where, in particular, a second stream 70 of sweetened gas isformed from a portion of the combustion effluent, it is preferable thatboth the division of sour gas between the streams, 54 and 56, fed to theoxy-combustion and conversion systems, 50 and 52, and the division ofthe combustion effluent 62 between being sent to the conversion system52 and being taken as the second stream 70 of sweetened gas, areadjustable so that both the desired reaction stoichiometry within theconversion system 52 and desired limits on SO_(x) content of theH₂S-lean, CO₂ product gas can be maintained in the event of a change inthe H₂S content of the sour gas streams 16, 18, 24, 54 and 56.

In the arrangement depicted in FIG. 2, sour gas streams 18, 54 and 56may for example comprise about 93% CO₂, 6.6% H₂, 0.4% CO, and 233 ppmH₂S. Combustion effluent 62 may comprise about 99% CO₂ and 235 ppmSO_(x). Stream 22 of sweetened gas may comprise about 96% CO₂ and 4%H₂/CO₂ (a second stream 70 of sweetened gas not, in this example, beingformed from the combustion effluent). The H₂S-lean, CO₂ product stream26 may then comprise about 5.2% H₂, 0.8% CO, 94% CO₂ and 71 ppm H₂S, andthe H₂S-lean, H₂-lean CO₂ product stream 36 may comprise about 99% CO₂,1% CO and 76 ppm H₂S. All the above figures are calculated on a drybasis.

Referring to FIG. 3, an alternative exemplary embodiment of the H₂Sremoval system is shown, the same reference numerals being used in FIG.3 as in FIG. 2 to denote common features. The removal system 20 in thisembodiment comprises both an oxy-fuel combustion system 50 and an H₂S toelemental sulfur conversion system 82 in which H₂S is converted toelemental sulfur via reaction with sulfuric acid (H₂SO₄) and/orsulfurous acid (H₂SO₃). Streams 54 and 56 of sour gas are, again, fed tothe combustion system 50 and conversion system 82, respectively, thecombustion system 50 combusting all or substantially all of the H₂, COand H₂S in sour gas stream 54 to form combustion effluent 62 comprisingCO₂, SO_(x) and H₂O, and the conversion system 82 converting all orsubstantially all of the H₂S in the sour gas stream 56 to elementalsulfur to provide stream 22 of sweetened gas and stream 68 of sulfur.Combustion effluent 62 is, again, passed through heat exchanger 64 torecover heat therefrom via indirect heat exchange.

In this arrangement, however, the combustion effluent 62 exiting heatexchanger 64 is introduced into SO_(x) to acid conversion system 80where it is cooled (in a further heat exchanger), compressed andmaintained at elevated pressure, in the presence of O₂, water andoptionally NO_(x), to convert all or substantially all of the SO_(x) inthe combustion effluent to H₂SO₄ and/or H₂SO₃, thereby forming a furtherstream 84 of sweetened gas and a stream 86 of aqueous H₂SO₄ and/orH₂SO₃. At least a portion of this acid (optionally, after evaporation ofsome of the water to obtain a more concentrated solution of acid) isthen introduced into the H₂S to elemental sulfur conversion system 82,the amount of acid fed into the conversion system preferably being atleast sufficient to provide the stoichiometric amount H₂SO₄ and/or H₂SO₃required for conversion of all of the H₂S in sour gas stream 56, whichproceeds according to the reactions 3H₂S(g)+H₂SO₄(l)→4S+4H₂O(l) and2H₂S(g)+H₂SO₃(l)→3S+3H₂O(l).

The heat recovered from the combustion effluent in heat exchanger 64 mayagain be supplied to the H₂S to elemental sulfur conversion system 82 asrequired for optimal conversion of H₂S, and/or put to other uses. Thestreams of sweetened gas 84 and 22 obtained from the SO_(x) to acidconversion system 80 and H₂S to elemental sulfur conversion system 82may be combined, as shown in FIG. 3, prior to being combined with sourgas stream 24 to form the H₂S-lean, CO₂ product, or the two streams ofsweetened gas may be separately added to stream 24 of sour gas.

It will be appreciated that the invention is not restricted to thedetails described above with reference to the preferred embodiments butthat numerous modifications and variations can be made without departingform the spirit or scope of the invention as defined in the followingclaims.

The invention claimed is:
 1. A method for treating a feed gas,comprising CO₂, H₂S and H₂, to produce an H₂-enriched product and anH₂S-lean, CO₂ product, the method comprising: separating the feed gas bypressure swing adsorption to form a stream of H₂-enriched product gasand a stream of sour gas, the sour gas also comprising CO₂, H₂S and H₂but being depleted in H₂ and enriched in H₂S and CO₂ relative to thefeed gas; dividing the stream of sour gas into two parts; processing onepart of said stream of sour gas in an H₂S removal system to form one ormore streams of sweetened gas, depleted in H₂S and enriched in CO₂relative to the feed gas; bypassing the H₂S removal system with theother part of said stream of sour gas; and combining said stream(s) ofsweetened gas with said sour gas bypassing the H₂S removal system toform a stream of H₂S-lean, CO₂ product gas; wherein the division of thesour gas between being sent to and processed in the H₂S removal systemand bypassing said system is adjusted responsive to changes in the H₂Scontent of the sour gas, such that the proportion of the sour gasprocessed in the H₂S removal system, as compared to bypassing saidsystem, is increased if the H₂S content rises and decreased if the H₂Scontent drops.
 2. The method of claim 1, wherein the feed gas has an H₂Sconcentration of from about 50 ppm to about 3 mole %.
 3. The method ofclaim 1, wherein the feed gas is a sour syngas mixture, comprising CO₂,H₂S, H₂ and CO, obtained from gasifying or reforming carbonaceousfeedstock.
 4. The method of claim 1, wherein the H₂-enriched product gascomprises at least about 90 mole % H₂ or a mixture of H₂ and CO, and isfree or substantially free of H₂S.
 5. The method of claim 1, wherein thesour gas comprises less than about 6 mole % H₂S.
 6. The method of claim1, wherein the or each stream of sweetened gas is free or substantiallyfree of H₂S.
 7. The method of claim 1, wherein the H₂S-lean, CO₂ productgas contains at most about 200 ppm H₂S.
 8. The method of claim 1,wherein the method further comprises separating the stream of H₂S-lean,CO₂ product gas to form an H₂S-lean, H₂-lean, CO₂ product and a secondH₂-enriched gas.
 9. The method of claim 8, wherein the H₂S-lean, CO₂product gas is separated by partial condensation or membrane separation.10. The method of claim 1, wherein the H₂S removal system comprises anadsorption system comprising one or more beds of adsorbent selective forH₂S, and the processing of sour gas in the H₂S removal system comprisespassing sour gas through said beds of adsorbent to adsorb H₂S therefromand form said or one of said stream(s) of sweetened gas.
 11. The methodof claim 1, wherein the H₂S removal system comprises a system forconverting H₂S to elemental sulfur, the processing of sour gas in theH₂S removal system comprising contacting sour gas with a reagent toconvert H₂S to elemental sulfur and form said or one of said stream(s)of sweetened gas.
 12. The method of claim 11, wherein the sour gascontains, in addition to H₂S, one or more other sulfur containingspecies, and wherein the method further comprises treating a portion orall of said sour gas to be processed in the H₂S to elemental sulfurconversion system to convert one or more of said sulfur containingspecies to H₂S prior to said sour gas being processed in said conversionsystem.
 13. The method of claim 1, wherein the H₂S removal systemcomprises a combustion system, and the processing of sour gas in the H₂Sremoval system comprises combusting sour gas in the presence of O₂ toproduce heat and a combustion effluent depleted in H₂S and H₂ andcomprising CO₂, SO_(x) and H₂O, SO_(x) being removed from saidcombustion effluent to form said or one of said stream(s) of sweetenedgas.
 14. The method of claim 13, wherein the combustion system is anoxy-fuel combustion system.
 15. The method of claim 13, wherein themethod further comprises passing the combustion effluent through a heatexchanger to recover heat therefrom via indirect heat exchange.
 16. Themethod of claim 13, wherein SO_(x) is removed from said combustioneffluent by cooling the combustion effluent to condense out water andconvert SO₃ to sulfuric acid, and maintaining the cooled combustioneffluent at elevated pressure(s), in the presence of O₂, water andoptionally NO_(x), for a sufficient time to convert SO₂ to sulfurousacid and/or SO₂ to sulfuric acid and NO_(x) to nitric acid.
 17. Themethod of claim 1, wherein the H₂S removal system comprises both acombustion system and a system for converting H₂S to elemental sulfurvia reaction with SO₂, sulfuric acid and/or sulfurous acid, and whereinthe sour gas to be processed in the H₂S removal system is divided intotwo streams, said processing comprising: contacting, in the H₂S toelemental sulfur conversion system, a stream of sour gas with SO₂,sulfuric acid and/or sulfurous acid to convert H₂S to elemental sulfurand form said stream or one of said streams of sweetened gas; andcombusting, in the combustion system, another stream of sour gas in thepresence of O₂ to produce heat and a combustion effluent depleted in H₂Sand H₂ and comprising CO₂, SO_(x) and H₂O, and: (i) introducing at leasta portion of the combustion effluent, or an SO₂-enriched streamseparated from the combustion effluent, into the H₂S to elemental sulfurconversion system to provide at least a portion of said SO₂ for thereaction with H₂S; and/or (ii) converting SO_(x) in the combustioneffluent to sulfuric and/or sulfurous acid, and introducing at least aportion of said acid into the H₂S to elemental sulfur conversion systemto provide at least a portion of said acid for the reaction with H₂S.18. The method of claim 17, wherein the H₂S to elemental sulfurconversion system converts H₂S to elemental sulfur via reaction withSO₂, and at least a portion of the combustion effluent, or anSO₂-enriched stream separated from the combustion effluent, isintroduced into said conversion system to provide at least a portion ofsaid SO₂ for the reaction with H₂S.
 19. The method of claim 18, whereinthe combustion effluent is divided into two streams thereof, one ofwhich is introduced into said conversion system to provide at least aportion of said SO₂ for the reaction with H₂S, and the other of whichforms a second of said streams of sweetened gas.
 20. The method of claim18, wherein the combustion effluent is separated to form an SO₂-enrichedstream and an SO₂-depleted stream, the SO₂-enriched stream is introducedinto said conversion system to provide at least a portion of said SO₂for the reaction with H₂S, and the SO₂-depleted stream forms a second ofsaid streams of sweetened gas.
 21. The method of claim 17, wherein theH₂S to elemental sulfur conversion system converts H₂S to elementalsulfur via reaction with sulfuric and/or sulfurous acid, SO_(x) in thecombustion effluent is converted to sulfuric and/or sulfurous acid, andat least a portion of said acid is introduced into said conversionsystem to provide at least a portion of said acid for the reaction withH₂S.
 22. The method of claim 21, wherein SO_(x) in the combustioneffluent is converted to sulfuric or sulfuric and sulfurous acid bycooling the combustion effluent to condense out water and convert SO₃ tosulfuric acid, and maintaining the cooled combustion effluent, atelevated pressure(s) in the presence of O₂, water and optionally NO_(x),for a sufficient time to convert SO₂ to sulfurous acid and/or SO₂ tosulfuric acid and NO_(x) to nitric acid.
 23. The method of claim 21,wherein the SO_(x)-depleted combustion effluent forms a second of saidstreams of sweetened gas.